DEMAND-SIDE MANAGEMENT ANNUAL REPORT SUPPLEMENT 1: COST EFFECTIVENESS

Transcription

1 DEMAND-SIDE MANAGEMENT 2018 ANNUAL REPORT MARCH SUPPLEMENT 1: COST EFFECTIVENESS

2 Printed on recycled paper

3 Table of Contents...1 Cost-Effectiveness...1 Methodology...2 Assumptions...3 Conservation Adder...6 Net-to-...6 Results DSM Detailed Expenses by Program...10 Cost-Effectiveness Tables by Program...14 Educational Distributions...14 Energy Efficient...16 Energy House Calls...18 Heating & Cooling Efficiency Program...20 Multifamily Energy Savings Program...23 Rebate Advantage...26 Residential New Construction Pilot Program...28 Shade Tree Project...30 Simple Steps, Smart Savings...31 Weatherization Assistance for Qualified Customers...33 Weatherization Solutions for Eligible Customers...34 Commercial Energy-Saving Kits...35 Custom Projects...37 New Construction...40 Retrofits...45 Irrigation Efficiency Rewards...54 Page i

4 List of Tables Table non-cost-effective measures...10 Table DSM detailed expenses by program (dollars)...11 Table 3. Cost-effectiveness of 2018 programs by B/C test...14 Page ii

5 Cost-Effectiveness Idaho Power considers cost-effectiveness of primary importance in the design, implementation, and tracking of energy efficiency and demand response programs. Idaho Power s energy efficiency and demand response opportunities are preliminarily identified through the Integrated Resource Plan (IRP) process. Idaho Power uses third-party energy efficiency potential studies to identify achievable costeffective energy efficiency potential, which is added to the resources included in the IRP. Idaho Power s Program Planning Group (PPG) explores new opportunities to expand current demand-side management (DSM) programs and offerings. Prior to the actual implementation of energy efficiency or demand response programs, Idaho Power performs a preliminary cost-effectiveness analysis to assess whether a potential program design or measure may be cost-effective from the perspective of Idaho Power and its customers. Incorporated in these models are inputs from various sources that use the most current and reliable information available. When possible, Idaho Power leverages the experiences of other utilities in the region and/ or throughout the country to help identify specific program parameters. This is accomplished through discussions with other utilities program managers and researchers. Idaho Power also uses electric industry research organizations, such as E Source, Northwest Energy Efficiency Alliance (NEEA) Regional Emerging Technology Advisory Committee, the Consortium for Energy Efficiency (CEE), American Council for an Energy-Efficient Economy (ACEEE), Advanced Load Control Alliance (ALCA), and Association of Energy Service Professionals (AESP), to identify similar programs and their results. Additionally, Idaho Power relies on the results of program impact evaluations and recommendations from consultants. Idaho Power s goal is for all programs to have benefit/cost (B/C) ratios greater than one for the total resource cost (TRC) test, utility cost test (UCT), and participant cost test (PCT) at the program and measure level where appropriate. Each cost-effectiveness test provides a different perspective, and Idaho Power believes each test provides value when evaluating program performance. If a measure or program is found to be not cost-effective from one or more of the three tests, Idaho Power assesses the program or measure and runs the cost-effectiveness calculations under a variety of scenarios. There are many assumptions when calculating the cost-effectiveness of a given program or measure. For some measures within the programs, savings can vary based on factors such participation levels or the participants locations. For instance, heat pumps installed in the Boise area will have less savings than heat pumps installed in the McCall area. If program participation and savings increase, fixed costs such as labor and marketing is spread out more and the program cost-effectiveness increases. When a program or measure is shown to be not cost-effective, Idaho Power works with Energy Efficiency Advisory Group (EEAG) to get additional input. If the measure or program is indeed offered, the company explains to stakeholders why the measure or program was implemented or continued and the steps the company plans to take to improve its cost-effectiveness. The company believes this aligns with the expectations of the Idaho Public Utilities Commission (IPUC) and Public Utility Commission Page 1

6 of Oregon (OPUC). In IPUC Order No , page 9, the IPUC states the following: We thus find it reasonable for the Company to continue screening potential programs using each test as a guideline, and to advise us on how the Company s programs fare under each test. When the Company ultimately seeks to recover its prudent investment in such programs, however, we believe the Company may (but need not exclusively) emphasize the UCT and that test s focus on Company-controlled benefits and costs to argue whether the programs were cost-effective. In the OPUC Order No , issued in Utility Miscellaneous (UM) 551, the OPUC outlines specific cost-effectiveness guidelines for energy efficiency measures and programs managed by program administrators. It is the expectation of the OPUC that measures and programs pass both the UCT and TRC tests. s and programs that do not pass these tests may be offered by a utility if they meet one or more of the following additional conditions specified by Section 13 of Order No : A. The measure produces significant non-quantifiable non-energy benefits (NEB) B. Inclusion of the measure will increase market acceptance and is expected to lead to reduced cost of the measure C. The measure is included for consistency with other DSM programs in the region D. Inclusion of the measure helps increase participation in a cost-effective program E. The package of measures cannot be changed frequently, and the measure will be cost-effective during the period the program is offered F. The measure or package of measures is included in a pilot or research project intended to be offered to a limited number of customers G. The measure is required by law or is consistent with OPUC policy and/or direction If Idaho Power determines a program or measure is not cost-effective but meets one or more of the exceptions set forth by Order No , the company files an exceptions request with the OPUC to continue offering the measure or program within it its Oregon service area. For operational and administrative efficiency, Idaho Power endeavors to offer identical programs in both its Oregon and Idaho jurisdictions. Some customers, contractors, and trade allies operate in both states. Program consistency is important for the participants overall satisfaction with the programs. Offering different program designs would create confusion in the marketplace and could inhibit participation. In addition, program infrastructure is designed to implement consistent programs across the service area. Methodology For its cost-effectiveness methodology, Idaho Power relies on the Electric Power Research Institute (EPRI) End Use Technical Assessment Guide (TAG); the California Standard Practice Manual and its Page 2

7 subsequent addendum, the National Action Plan for Energy Efficiency s (NAPEE) Understanding Cost Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers; and the National Action Plan on Demand Response. For resource planning, Idaho Power uses the TRC test. This test is used because, as defined in the TAG and California Standard Practice Manual, it is the most like supply-side tests and provides a useful basis to compare demandside and supply-side resources. For program planning and evaluation, the company uses the TRC and the UCT test to develop B/C ratios to determine the cost-effectiveness of DSM programs. The PCT provides the company the opportunity to assess a program or measure from the participant perspective and to determine if it is in the best interest of the average customer. For energy efficiency programs, each program s cost-effectiveness is reviewed annually from a oneyear perspective. The annual energy-savings benefit value is summed over the life of the measure or program and is discounted to reflect 2018 dollars. The result of the one-year perspective is shown in. The goal of demand response programs is to minimize or delay the need to build new supply-side resources. Unlike energy efficiency programs or supply-side resources, demand response programs must acquire and retain participants each year to maintain a level of demand-reduction capacity for the company. As part of the public workshops on Case No. IPC-E-13-14, Idaho Power and other stakeholders agreed on a new methodology for valuing demand response. The settlement agreement, as approved in IPUC Order No and OPUC Order No , defined the annual cost of operating the three demand response programs for the maximum allowable 60 hours to be no more than $16.7 million. The annual value calculation will be updated with each IRP based on changes that include, but are not limited to, need, capital cost, or financial assumptions. This amount was reevaluated in the 2015 IRP to be $18.5 million and again in the 2017 IRP to be $19.8 million. This value is the levelized annual cost of a 170-megawatt (MW) deferred resource over a 20-year life. The demand response value calculation will include this value even in years when the IRP shows no peak-hour capacity deficits. In 2018, the cost of operating the three demand response programs was $8.2 million. Idaho Power estimates that if the three programs were dispatched for the full 60 hours, the total costs would have been approximately $11.3 million and would have remained cost-effective. Assumptions Idaho Power relies on research conducted by third-party sources to obtain savings and cost assumptions for various measures. These assumptions are routinely reviewed internally and with EEAG and updated as new information becomes available. For many of the measures within Supplement 1: Cost Effectiveness, savings and costs were derived from the Regional Technical Forum (RTF), the technical reference manual (TRM), or the Idaho Power Energy Efficiency Potential Study conducted by Applied Energy Group (AEG). Idaho Power received end-use load shapes from AEG, which have been applied to each program and measure when applicable. Idaho Power used updated assumptions Page 3

8 from the 2016 potential study for the 2018 cost-effectiveness analyses. Due to the timing of the 2018 potential study, Idaho Power will use any updated assumptions from the 2018 study in The RTF regularly reviews, evaluates, and recommends eligible energy efficiency measures and the estimated savings and costs associated with those measures. For instance, because of the rapid changes in the lighting market, the RTF is currently evaluating lighting measures on an annual basis. As the RTF updates these assumptions, Idaho Power applies them to current program offerings and assesses the need to make any program changes. Idaho Power staff participates in the RTF by attending monthly meetings and contributing to various sub-committees. Because cost data from the RTF information is in 2012 dollars, measures with costs from the RTF are escalated to 2018 dollars. The costs are escalated by 7.8 percent. This percentage is provided by the RTF in workbook RTFStandardInformationWorkbook_ v3_2.xlsx. Idaho Power uses a TRM developed by ADM Associates, Inc. for the Commercial and Industrial Energy Efficiency Program s New Construction and Retrofit options. In 2018, the company contracted with ADM to update the TRM. Idaho Power also relies on other sources, such as the Northwest Power and Conservation Council (NWPCC), Northwest Energy Efficiency Alliance (NEEA), the Database for Energy Efficiency Resources (DEER), the Energy Trust of Oregon (ETO), the Bonneville Power Administration (BPA), third-party consultants, and other regional utilities. Occasionally, Idaho Power will also use internal engineering estimates and calculations for savings and costs based on information gathered from previous projects. The company freezes savings assumptions when the budgets and goals are established for the next calendar year unless code and standard changes or program updates necessitate a need to use updated savings. These assumptions are discussed in more detail in the cost-effectiveness sections for each program. As a rule, the 2018 energy savings reported for most programs will use the assumption set at the beginning of the year. An exception would be the Commercial & Industrial Energy Efficiency program. Once the TRM was updated, the company launched changes to the program in August For applications initiated before the change date, the TRM version 1.7 was the source for most savings and cost assumptions for the New Construction and Retrofit options. For applications initiated after the change date, the current TRM version 2.2 is the source for most savings and cost assumptions for the program. The remaining inputs used in the cost-effectiveness models are obtained from the IRP process. Idaho Power s 2015 IRP was acknowledged by the IPUC on December 23, 2015 and by the OPUC April 28, 2016 and is the source of all the financial assumptions for the cost-effectiveness analysis. Appendix C Technical Appendix of Idaho Power s 2015 IRP contains the DSM alternative costs, discount rate, and escalation rate. These DSM alternative costs vary by season and time of day and are applied to an end-use load shape to obtain the value of that particular measure or program. The DSM alternative energy costs are based on both the projected fuel costs of a peaking unit and forward electricity prices as determined by Idaho Power s power supply model, AURORAxmp Electric Market Model. The avoided capital cost of capacity is based on a gas-fired, simple-cycle turbine. In the 2015 IRP, the annual avoided capacity cost is $119 per kilowatt (kw). Page 4

9 As part of the 2015 IRP Case IPC-E and 2014 DSM prudence Case IPC-E-15-06, parties requested Idaho Power review how transmission and distribution (T&D) costs are treated in the IRP. Idaho Power committed to reviewing the T&D benefits, and the analysis was presented to EEAG in August The estimated average value of energy efficiency on T&D deferral is $3.76/kW per year or $ /kilowatt-hour (kwh). In compliance with Order No , this value is escalated and added to the 2015 DSM alternative energy costs and included in the cost-effectiveness analysis for Idaho Power s 2017 IRP was filed on June 30, 2017 with the IPUC under case IPC-E and with the OPUC under case LC 68. Idaho Power s 2017 IRP was acknowledged by the IPUC on February 9, 2018 in Order No and in by the OPUC on May 23, 2018 in Order No Since the 2017 IRP was acknowledged after the budgets and goals were set for 2018, the 2015 IRP remained the source for all financial assumptions and cost-effectiveness analysis in The 2017 IRP is expected to be the source of all assumptions and analysis for the 2019 program year. For the demand response programs, with inputs from the 2017 IRP, the Company determined the maximum annual cost of running all three demand response programs for the maximum allowable hours of 60 hours has been calculated to be no more than $19.8 million. As recommended by the NAPEE Understanding Cost-Effectiveness of Energy Efficiency Programs Idaho Power s weighted average cost of capital (WACC) of 6.74 percent is used to discount future benefits and costs to today s dollars. Once the DSM alternative costs and load shapes are applied to the annual kwh savings of a measure or program, the WACC is used to calculate the net present value (NPV) of the annual benefit for the UCT and TRC B/C ratios. However, determining the appropriate discount rate for participant cost and benefits is difficult because of the variety of potential discount rates that can be used by the different participants as described in the TAG. Since the participant benefit is based on the anticipated bill savings of the customer, Idaho Power believes the WACC is not an appropriate discount rate to use. Because the customer bill savings is based on Idaho Power s 2018 average customer segment rate and is not escalated, the participant bill savings is discounted using a real discount rate of 4.44 percent, which is based on the 2015 IRP s WACC of 6.74 percent and an escalation rate of 2.2 percent. The real discount rate is used to calculate the NPV of any participant benefits or costs for the PCT or ratepayer impact measure (RIM) B/C ratios. The formula to calculate the real discount rate is as follows: ((1 + WACC) (1 + Escalation)) 1 = Real Line-loss percentages are applied to the metered-site energy savings to find the energy savings at the generation level. The shows the estimated electrical savings at the customer meter level. Cost-effectiveness analyses are based on generation-level energy savings. The demand response program reductions are reported at the generation level with the line losses. The average system line-loss factor is 9.6 percent while the summer peak line-loss factors is 9.7 percent. Page 5

10 Conservation Adder The Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act) states the following: any conservation or resource shall not be treated as greater than that of any non conservation measure or resource unless the incremental system cost of such conservation or resource is in excess of 110 per centum of the incremental system cost of the nonconservation measure or resource. As a result of the Northwest Power Act, most utilities in the Pacific Northwest add a 10-percent conservation adder in energy efficiency cost-effectiveness analyses. In OPUC Order No , the OPUC states: We support the staff s position that the effect of conservation in reducing uncertainty in meeting load growth is included in the ten percent cost adder and that no separate adjustment is necessary. Additionally, in IPUC Order No in Case No. GNR-E-12-01, Staff noted that Rocky Mountain Power and Avista use a 10 percent conservation adder when calculating the cost-effectiveness of all their DSM programs. Staff recommended the utilities have the option to use a 10-percent adder, and the IPUC agreed with the recommendation to allow utilities to use the 10-percent adder in the costeffectiveness analyses for low-income programs. After reviewing the s of other utilities in the Pacific Northwest, as well as the OPUC Order No and IPUC Order 32788, Idaho Power applies the 10-percent conservation adder in all energy efficiency measure and program cost-effectiveness analyses when calculating the TRC test. Net-to- Net-to-gross (NTG), or net-of-free-ridership (NTFR), is defined by NAPEE s Understanding Cost Effectiveness of Energy Efficiency Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers as a ratio that does as follows: Adjusts the impacts of the programs so that they only reflect those energy efficiency gains that are the result of the energy efficiency program. Therefore, the NTG deducts energy savings that would have been achieved without the efficiency program (e.g., free-riders ) and increases savings for any spillover effect that occurs as an indirect result of the program. Since the NTG attempts to measure what the customers would have done in the absence of the energy efficiency program, it can be difficult to determine precisely. Capturing the effects of Idaho Power s energy efficiency efforts on free-ridership and spillover is difficult. Due to the uncertainty surrounding NTG percentages, Idaho Power used an NTG of Page 6

11 100 percent for all measure cost-effectiveness analyses. For the program cost-effectiveness analyses, the B/C ratios shown are based on a 100-percent NTG. A sensitivity analysis was conducted to show what the minimum NTG percentage needs to be for the program to remain (or become) cost effective from either the TRC or UC perspective. These NTG percentages are shown in the program cost effectiveness results in. Results Idaho Power determines cost-effectiveness on a measure basis, where relevant, and program basis. As part of and where applicable, Idaho Power publishes the cost-effectiveness by measure, calculating the PCT and RIM test at the program level, listing the assumptions associated with cost-effectiveness, and citing sources and dates of metrics used in the cost-effectiveness calculation. The B/C ratio from the participant cost perspective is not calculated for the Commercial Energy-Saving Kits, Educational Distributions, Energy House Calls, Multifamily Energy Savings Program, Shade Tree Project, Weatherization Assistance for Qualified Customers (WAQC), and Weatherization Solutions for Eligible Customers programs. These programs have few or no customer costs. For energy efficiency programs, the cost-effectiveness models do not assume ongoing participant costs. contains annual cost-effectiveness metrics for each program using actual information from 2018 and includes results of the UCT, TRC, PCT, and RIM. Current average customer energy rates are used in the calculation of the B/C ratios from a PCT and RIM perspective. Rate increases are not forecasted or escalated. A summary of the cost-effectiveness by program can be found in Table 3. In 2018, most of Idaho Power s energy efficiency programs were cost-effective, except for Heating & Cooling Efficiency (H&CE) Program, Shade Tree Project, and the weatherization programs for income-qualified customers. The H&CE Program has a UC of 1.65, TRC of 0.83, PCT of Idaho Power first notified EEAG in August 2016 that the program was anticipated to be not cost-effective from the TRC perspective. Idaho Power has continued to update EEAG of its efforts to improve the program s cost-effectiveness. Throughout 2017 and into 2018, Idaho Power worked toward improving program cost-effectiveness. These tactics included: 1) reassigning non-program labor, 2) reducing marketing spend while improving other tactics, 3) reducing contractor incentives from $150 to $50, and 4) adding heat pump water heaters to the program. These efforts were successful in keeping cost-effectiveness ratios from falling in 2018 over 2017 levels. However, calibrations to end-use load shapes created for the 2016 energy efficiency potential study offset cost-effectiveness gains from cost control efforts in Had Idaho Power used the same load shape as was used for the 2017 program year, the program would have had a TRC just over 1.0. Page 7

12 Due to their high costs, DHPs continue to bring down the cost-effectiveness of the program. The DHP portion of the program has a UCT of 1.37 and TRC 0.69 while the rest of the program has a UCT of 1.82 and TRC of Market transformation efforts, specifically the market transformation work provided by NEEA, in the region have failed to drive prices down along with lower net savings in colder climates are the two primary problems plaguing DHP cost-effectiveness. When the company began the Shade Tree Project in 2013, the initial analysis showed that the project would be cost-effective from the UCT and TRC perspective based on preliminary assumptions and then-current DSM alternate costs. The company s intent was to begin claiming savings when the original planted trees were five years old. Since the Shade Tree Project began in 2013, 2018 was the first year Idaho Power claimed savings and calculating the cost-effectiveness for the Shade Tree Project. This project is shown to have a UCT of 0.71, a TRC of The cost-effectiveness for the program is based on the modeled savings for the tree distributed in 2018 and the costs incurred during It is estimated that these trees will begin saving 35,425 kwh in 2022 and 116,197 kwh by year DNV GL created a new savings model to adjust the savings from the enrollment calculator using the data from Idaho Power s audit of the project. The audit provided information on where the trees were actually planted and the tree mortality. The new savings model calculates the average savings per tree and assumed a measure life of 20 years. This is because the enrollment software, i-tree, used by the Arbor Day Foundation only estimates saving at 5, 10, 15, and 20 years. In 2018, the bur oak, northern red oak, Greenspire littleleaf linden, and tulip tree were the most common species distributed in the project. According to the ed States Department of Agriculture and the Urban Forest Ecosystem Institute, these trees can live up to 500 years. Idaho Power acknowledges that the potential energy savings for a tree may continue to increase beyond year 20, but the savings will be capped at some point regardless of how large the tree grows. For trees distributed in 2018, data around the survivorship of the tree beyond 2038 is also unknown. While the energy saving in 2038 is estimated to be 116,197 kwh, the savings may continue to increase at a diminishing rate before eventually declining due to increased mortality. However, if energy savings were to stay constant beyond year 20, it can be assumed that program would be cost-effective from the UCT and TRC perspective if the program life was revised to 30 years. WAQC had a TRC of 0.52 and a UCT ratio of 0.43, and Weatherization Solutions for Eligible Customers had a TRC of 0.51 and a UCT ratio of The programs cost-effectiveness ratios increased slightly over 2017 s ratios. To calculate the programs cost-effectiveness, Idaho Power adopted the following IPUC staff s recommendations from Case No. GNR E-12-01: Applied a 100-percent NTG. Claimed 100 percent of energy savings for each project. Included indirect administrative overhead costs. The overhead costs of percent were calculated from the $1,335,208 of indirect program expenses divided by the total DSM expenses of $44,262,080 as shown in Appendix 3 of the. Page 8

13 Applied the 10 percent conservation preference adder. Amortized evaluation expenses over a three-year period. Claimed one dollar of NEBs for each dollar of utility and federal funds invested in health, safety, and repair measures. Eighteen out of 279 individual measures in various programs are shown to not be cost-effective from either the UCT or TRC perspective. These measures will be discontinued, analyzed for additional NEBs, modified to increase potential per-unit savings, or monitored to examine their impact on the specific program s overall cost-effectiveness. Specifically, of the 18 non-cost-effective measures, and seven have ratios between and three have ratios between For most of these measures, Idaho Power filed cost-effectiveness exception requests with the OPUC in compliance with Order No s and programs that do not pass these tests may be offered by the utility if they meet one or more of the additional conditions specified by Section 13 of Order No These exception requests were approved under Order No on June 23, 2015, or with the specific program advice filings. The filings and exception requests are noted in Table 1. Table non-cost-effective measures Program Number of s Notes H&CE Program 7 Cost-effectiveness exception request for ductless heat pumps (DHP) and open-loop water source heat pumps filed with the OPUC under UM OPUC Order No , Section 13. Approved under Order No Exception request for the program and smart thermostat requested and approved with OPUC Advice No Heat pump water heaters and duct sealing measures would be cost-effective at 1.00 and 1.16 respectively without the inclusion of administration costs. Meets OPUC Order No , Section 10. Rebate Advantage 1 Eco-Rated manufactured homes built in Heating Zone 1 and Cooling Zone 3 has a TRC of s would be cost-effective with TRC of 1.10 without the inclusion of administration costs. Meets OPUC Order No , Section 10. New Construction and Retrofits 5 s offered in both options. Cost-effectiveness exception request filed and approved with OPUC Advice No OPUC Order No , Section 13. Exceptions B, C, and D. Retrofit 5 UCT and TRC ranges from 0.85 to Cost-effectiveness exception request filed and approved with OPUC Advice No OPUC Order No , Section 13. Exceptions B, C, and D. Total 18 Following the annual program cost-effectiveness results are tables that include measure-level cost effectiveness. Exceptions to the measure-level tables are programs that are analyzed at the project level. These programs include Custom Projects, the custom option of Irrigation Efficiency Rewards, Shade Tree, WAQC, and Weatherization Solutions for Eligible Customers. The measure-level cost-effectiveness includes inputs of measure life, energy savings, incremental cost, incentives, program administration cost, and net benefit. Program administration costs include all non incentive costs: labor, marketing, training, education, purchased services, and evaluation. Energy and expense data have been rounded to the nearest whole unit. Page 9

14 2018 DSM Detailed Expenses by Program Included in this supplement is a detailed breakout of program expenses as shown in Appendix 2 of the Demand Side Management 2018 Annual Report. These expenses are broken out by funding source major-expense type (labor/administration, materials, other expenses, purchased services, and incentives). Table DSM detailed expenses by program (dollars) Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Energy Efficiency/Demand Response Total $ 27,584,031 $ 1,199,257 $ 1,495,429 $ 30,278,718 Residential Total $ 8,620,729 $ 244,628 $ 1,445,147 $ 10,310,503 Easy Savings: Low-Income Energy Efficiency Education , ,936 Labor/Administrative Expense... 22,351 22,351 Materials and Equipment , ,046 Other Expense Purchased Services Educational Distributions... 3,307,782 67,409 3,375,192 Labor/Administrative Expense... 47,054 2,475 49,529 Materials and Equipment... 2,207,759 48,124 2,255,883 Purchased Services... 1,052,970 16,810 1,069,780 Energy Efficient... 2,343,127 92,003 2,435,130 Incentives... 1,214,018 43,082 1,257,100 Labor/Administrative Expense... 53,094 2,795 55,889 Other Expense ,614 10, ,251 Purchased Services ,401 35, ,890 Energy House Calls ,712 14, ,777 Labor/Administrative Expense... 11, ,582 Materials and Equipment... 8, ,088 Other Expense... 17, ,365 Purchased Services ,634 12, ,742 Fridge and Freezer Recycling Program... 33, ,907 Labor/Administrative Expense Materials and Equipment... 1, ,424 Other Expense... (0) 0 (0) Purchased Services... 31, ,728 Heating & Cooling Efficiency Program ,780 19, ,211 Labor/Administrative Expense ,579 5, ,398 Materials and Equipment... 6,766 (394) 6,372 Other Expense... 69,186 2,048 71,235 Purchased Services... 80,408 3,432 83,841 Incentives ,840 8, ,365 Home Energy Audit , ,394 Labor/Administrative Expense... 57,485 57,485 Materials and Equipment... 21,971 21,971 Other Expense... 50,619 50,619 Purchased Services , ,318 Multifamily Energy Savings Program , ,131 Labor/Administrative Expense... 64,221 64,221 Materials and Equipment... 38,442 38,442 Other Expense... 37,138 37,138 Purchased Services... 65,330 65,330 Oregon Residential Weatherization... 5,507 5,507 Labor/Administrative Expense... 3,737 3,737 Other Expense Incentives Page 10

15 Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Rebate Advantage ,770 41, ,483 Labor/Administrative Expense... 13, ,458 Other Expense... 4, ,622 Purchased Services... 14,596 6,808 21,404 Incentives... 73,000 34, ,000 Residential New Construction Pilot Program , ,912 Labor/Administrative Expense... 59,151 59,151 Materials and Equipment... 3,884 3,884 Other Expense... 12,811 12,811 Purchased Services... 6, ,067 Incentives , ,000 Shade Tree Project , ,995 Labor/Administrative Expense... 36,276 36,276 Materials and Equipment Other Expense... 9,554 9,554 Purchased Services , ,736 Simple Steps, Smart Savings... 86,721 3,762 90,484 Labor/Administrative Expense... 38,029 2,001 40,031 Purchased Services... 10, ,096 Incentives... 38,019 1,339 39,357 Weatherization Assistance for Qualified Customers 1,272,973 1,272,973 Labor/Administrative Expense... 43,402 43,402 Other Expense... 1,555 1,555 Purchased Services... 1,228,017 1,228,017 Weatherization Solutions for Eligible Customers 998,233 24,237 1,022,471 Labor/Administrative Expense... 6,031 24,237 30,268 Other Expense... 24,403 24,403 Purchased Services , ,799 Commercial/Industrial $ 16,281,639 $ 720,714 $ 12,156 $ 17,014,509 Custom Projects... 8,400, ,860 12,156 8,808,512 Labor/Administrative Expense ,640 29,713 12, ,420 Other Expense ,090 24, ,067 Purchased Services... 1,187,801 72,463 1,260,263 Incentives... 6,295, ,797 6,564,762 New Construction... 2,004,058 65,587 2,069,645 Labor/Administrative Expense ,780 9, ,504 Other Expense... 8, ,296 Purchased Services ,927 4, ,618 Incentives... 1,672,520 50,706 1,723,226 Retrofits... 5,732, ,529 5,990,179 Labor/Administrative Expense ,658 15, ,272 Materials and Equipment Other Expense... 26,392 1,389 27,781 Purchased Services ,604 37, ,425 Incentives... 4,690, ,668 4,892,975 Commercial Education Initiative ,436 1, ,174 Labor/Administrative Expense... 4, ,911 Materials and Equipment ,780 1, ,924 Other Expense... (5,106) (269) (5,375) Purchased Services... 37, ,714 Page 11

16 Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Irrigation Total $ 2,681,664 $ 233,916 $ 38,126 $ 2,953,706 Irrigation Efficiency Rewards... 2,681, ,916 38,126 2,953,706 Labor/Administrative Expense ,129 17,685 38, ,826 Materials and Equipment... 7, ,334 Other Expense... 30,133 1, ,226 Purchased Services... 4, ,103 Incentives... 2,302, ,663 2,516,217 Market Transformation Total $ 2,375,157 $ 125,008 $ $ 2,500,165 NEAA... 2,375, ,008 2,500,165 Purchased Services... 2,375, ,008 2,500,165 Other Program and Activities Total $ 1,878,538 $ 99,474 $ 558 $ 1,978,570 Commercial/Industrial Energy Efficiency Overhead 444,787 23, ,396 Labor/Administrative Expense ,350 16, ,913 Materials and Equipment Other Expense ,461 5, ,192 Purchased Services... 24,819 1,306 26,125 Energy Efficiency Direct Program Overhead ,437 11, ,302 Labor/Administrative Expense ,075 9, ,079 Other Expense... 54,362 2,861 57,223 Home Improvement... 2,926 2,926 Labor/Administrative Expense Other Expense Purchased Services... 2,525 2,525 Oregon Commercial Audit... 1,473 1,473 Labor/Administrative Expense Other Expense Residential Energy Efficiency Education Initiative ,255 8, ,215 Labor/Administrative Expense... 85,459 4,498 89,957 Materials and Equipment... 1, ,247 Other Expense... 74,862 4,308 79,170 Purchased Services... 1, ,841 Residential Energy Efficiency Overhead... 1,042,132 54,125 1,096,257 Labor/Administrative Expense ,796 9, ,263 Other Expense ,918 42, ,920 Purchased Services... 53,418 2,657 56,075 Indirect Program Expenses Total $ 1,101,937 $ 52,565 $ 180,706 $ 1,335,208 All Sectors Total $ 1,101,937 $ 52,565 $ 180,706 $ 1,335,208 Energy Efficiency Accounting and Analysis ,281 51, ,706 1,219,241 Labor/Administrative Expense ,690 28, , ,715 Materials and Equipment Other Expense... 20,826 20,826 Purchased Services ,084 23, ,166 Energy Efficiency Advisory Group... 16, ,724 Labor/Administrative Expense... 6, ,924 Other Expense... 10, ,799 Special Accounting Entries... 97, ,243 Special Accounting Entry... 97, ,243 Page 12

17 Sector/Program Idaho Rider Oregon Rider Idaho Power Total Program Demand Response Total $ 723,339 $ 281,606 $ 7,164,475 $ 8,169,419 Residential Total $ 433,659 $ 36,425 $ 374,285 $ 844,369 A/C Cool Credit ,659 36, , ,369 Labor/Administrative Expense... 63,912 3,360 67,271 Materials and Equipment... (11,709) 1 (11,708) Other Expense... 15, ,588 Purchased Services ,697 27, ,981 Incentives... 4, , ,237 Commercial/Industrial Total $ 58,727 $ 64,316 $ 310,270 $ 433,313 Flex Peak Program... 58,727 64, , ,313 Labor/Administrative Expense... 58,727 3,090 61,816 Incentives... 61, , ,496 Irrigation Total $ 230,953 $ 180,865 $ 6,479,919 $ 6,891,737 Irrigation Peak Rewards , ,865 6,479,919 6,891,737 Labor/Administrative Expense... 90,337 4,754 12, ,836 Materials and Equipment... 65,078 2,808 67,887 Other Expense... 2, ,476 Purchased Services... 73,185 3,843 77,028 Incentives ,335 6,467,175 6,636,510 Grand Total $ 33,663,001 $ 1,757,910 $ 8,841,168 $ 44,262,080 Table 3. Cost-effectiveness of 2018 programs by B/C test Program/Sector UCT TRC RIM PCT Educational Distributions N/A Energy Efficient Energy House Calls N/A Heating & Cooling Efficiency Program Multifamily Energy Savings Program N/A Rebate Advantage Residential New Construction Pilot Program Shade Tree Project N/A Simple Steps, Smart Savings Weatherization Assistance for Qualified Customers N/A Weatherization Solutions for Eligible Customers N/A Residential Energy Efficiency Sector Commercial Energy-Saving Kits N/A Custom Projects New Construction Retrofits Commercial/Industrial Energy Efficiency Sector* Irrigation Efficiency Rewards Irrigation Energy Efficiency Sector** Energy Efficiency Portfolio *Commercial/Industrial Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Rewinds. **Irrigation Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Rewinds. Page 13

18 Educational Distributions Segment: Residential 2018 Program Results Cost-Effectiveness Tables by Program Cost Inputs Program Administration... $ 3,375,192 Program Incentives... I Total UC... $ 3,375,192 P Equipment and Installation (Incremental Participant Cost)... $ M Summary of Cost-Effectiveness Results Test Benefit Cost Ratio UC Test... $ 9,054,951 $ 3,375, TRC Test... 15,211,587 3,375, RIM Test... 9,054,951 15,670, PCT... N/A N/A N/A Net Benefit Inputs (NPV) Resource Savings 2018 Annual Energy (kwh)... 19,333,668 NPV Cumulative Energy (kwh) ,251,153 $ 9,054,951 S 10% Credit (Northwest Power Act) ,495 Total Electric Savings... $ 9,960,446 A Participant Bill Savings NPV Cumulative Participant Bill Savings... $ 12,295,058 B Other Benefits Non-Utility Rebates/Incentives... $ NUI NEBs... $ 5,251,140 NEB Benefits and Costs Included in Each Test UC Test... = S * NTG = P TRC Test... = (A + NUI + NEB) * NTG = P RIM Test... = S * NTG = P + (B * NTG) PCT... N/A N/A Assumptions for Levelized Calculations Discount Rate Nominal (WACC) % Real ((1 + WACC) / (1 + Escalation)) % Escalation Rate % Net-to- (NTG) % Minimum NTG Sensitivity... 38% Average Customer Segment Rate/kWh... $0.085 Line Losses % Notes: Energy savings as reported by the Resource Action Plan for the 2017 to 2018 student kits. NEBs for giveaway bulbs, welcome kit bulbs, and energy-saving kits include PV of periodic bulb (capital) replacement costs. NEBs for student kit and energy-savings kit showerheads include the NPV of water and wastewater savings and, when applicable, therm savings. No participant costs. Page 14

19 Year: 2018 Program: Educational Distributions Market Segment: Residential Program Type: Energy Efficiency Name Descriptions Replacing General Purpose LED Give away Student Energy Efficiency Kit (SEEK) Program Energy-Saving Kit weighted average of non-electric and electric kit Energy-Saving Kit (giveaway lightbulb only kit) Welcome Kit (lightbulb only kit) Home Energy Reports Efficient Technology: LED Lamp Type: General Purpose and Dimmable Lumen Category: 250 to 1049 lumens Space Type: ANY kit offering. Kits include: highefficiency showerhead, shower timer, 3 LEDs, FilterTone alarm, digital thermometer, LED nightlight to 1049 lumen General Purpose bulbs gpm showerhead and thermostatic shower valve combo (electric kit only) 3 - faucet aerators (electric kit only) to 1049 lumen General Purpose bulbs to 1049 lumen General Purpose bulbs Home energy report End Use Baseline bulb Lamp Residential-All- -All Life (yrs) a Energy Savings (kwh/yr) b Benefit Cost B/C Tests NPV DSM Avoided Costs c NEB Incremental Participant Cost d Incentive/ Admin Cost ($/kwh) e UCT Ratio f TRC Ratio g Source $4.66 $3.53 $ No kit Kit IPC_Student Kits $ $10.83 $ No kit Kit IPC_Energy-savings Kits (weighted) No kit Kit Residential-All- -All No kit Kit Residential-All- -All No behavior change Report IPC_Home Energy Reports $ $ $ $41.98 $31.79 $ $18.66 $14.13 $ $9.80 $ a Average measure life. b Estimated kwh savings measured at the customer s meter, excluding line losses. c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2015 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act. d No participant costs. e Average program administration and overhead costs to achieve each kwh of savings for each initiative. Calculated from 2018 actuals. f UCT Ratio = (NPV DSM Avoided Costs) / ((Admin Cost/kWh * kwh Savings) + Incentives) g TRC Ratio = ((NPV DSM Avoided Costs * 110%) + NEB / ((Admin Cost/kWh * kwh Savings) + Incentives + (Incremental Participant Cost - Incentives)) 1 RTF. Res_Bulbs_v5_2.xlsm Resource Action Programs Idaho Power Energy Wise Program Summary Report Lightbulbs - RTF. Res_Bulbs_v5_2.xlsm. Showerhead - RTF. ResShowerheads_v3_1.xlsm. Faucet aerators - ETO. Approval Document for Energy Saver Kits. 4 Idaho Power HER Year 1 Final Program Summary. Aclara Page 15

20 Energy Efficient Segment: Residential 2018 Program Results Cost Inputs Program Administration... $ 1,178,030 Program Incentives... 1,257,100 I Total UC... $ 2,435,130 P Equipment and Installation (Incremental Participant Cost) $ 2,099,009 M Summary of Cost-Effectiveness Results Test Benefit Cost Ratio UC Test... $ 11,376,534 $ 2,435, TRC Test... 21,769,861 3,277, RIM Test... 11,376,534 19,319, PCT... 27,397,594 2,099, Net Benefit Inputs (NPV) Resource Savings 2018 Annual Energy (kwh)... 18,856,933 NPV Cumulative Energy (kwh) ,790,823 $ 11,376,534 S 10% Credit (Northwest Power Act)... 1,137,653 Total Electric Savings... $ 12,514,187 A Participant Bill Savings NPV Cumulative Participant Bill Savings... $ 16,884,819 B Other Benefits Non-Utility Rebates/Incentives... $ NUI NEBs... $ 9,255,674 NEB Benefits and Costs Included in Each Test UC Test... = S * NTG = P TRC Test... = (A + NUI + NEB) * NTG = P + ((M-I) * NTG) RIM Test... = S * NTG = P + (B * NTG) PCT... = B + I + NUI + NEB = M Assumptions for Levelized Calculations Discount Rate Nominal (WACC) % Real ((1 + WACC) / (1 + Escalation)) % Escalation Rate % Net-to- (NTG) % Minimum NTG Sensitivity... 22% Average Customer Segment Rate/kWh... $0.085 Line Losses % Note: NEBs include PV of periodic bulb (capital) replacement costs. Page 16

21 Year: 2018 Program: Energy Efficient Market Segment: Residential Program Type: Energy Efficiency Name Descriptions Replacing Decorative and Mini-Base General Purpose, Dimmable, and Three- Way General Purpose, Dimmable, and Three- Way General Purpose, Dimmable, and Three- Way Globe Globe Globe lectors and Outdoor lectors and Outdoor lectors and Outdoor LED Fixture Retailer LED Fixture Retailer Retail_LED_Decorative and Mini-Base_250 to 1049 lumens Retail_LED_General Purpose, Dimmable, and Three-Way_250 to 1049 lumens Retail_LED_General Purpose, Dimmable, and Three-Way_1050 to 1489 lumens Retail_LED_General Purpose, Dimmable, and Three-Way_1490 to 2600 lumens Retail_LED_Globe_250 to 1049 lumens Retail_LED_Globe_1050 to 1489 lumens Retail_LED_Globe_1490 to 2600 lumens Retail_LED_lectors and Outdoor_250 to 1049 lumens Retail_LED_lectors and Outdoor_1050 to 1489 lumens Retail_LED_lectors and Outdoor_1490 to 2600 lumens LED Indoor Fixture LED Outdoor Fixture Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Baseline bulb Fixture Fixture Fixture Fixture Fixture Fixture Fixture Fixture Fixture Fixture End Use Residential All- Residential All- Residential All- Residential All- Residential All- Residential All- Residential All- Residential All- Residential All- Residential All- Benefit Cost B/C Tests Annual Energy NPV DSM Incremental Admin Savings Avoided Participant Incentive/ Cost TRC Life (yrs) a (kwh/yr) b Costs c NEB Cost d ($/kwh) e UCT Ratio f Ratio g Source $7.46 $6.96 $- $0.50 $ $5.84 $3.85 $1.27 $0.50 $ $10.28 $6.42 $4.66 $0.50 $ $5.97 $4.39 $4.01 $0.50 $ $6.91 $6.85 $2.88 $0.50 $ $8.29 $6.32 $3.10 $0.50 $ $7.97 $4.50 $2.94 $0.50 $ $13.38 $12.74 $1.12 $2.00 $ $12.02 $16.70 $3.68 $2.00 $ $41.02 $72.05 $5.65 $5.00 $ Fixture Residential All $18.70 $18.15 $2.02 $1.80 $ Fixture IPC Outdoor $16.26 $11.81 $2.22 $2.91 $ a Average measure life. b Estimated kwh savings measured at the customer s meter, excluding line losses. c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2015 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act. d Incremental participant cost prior to customer incentives. e Average program administration and overhead costs to achieve each kwh of savings. Calculated from 2018 actuals. f UCT Ratio = (NPV DSM Avoided Costs) / ((Admin Cost/kWh * kwh Savings) + Incentives) g TRC Ratio = ((NPV DSM Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kwh Savings) + Incentives + (Incremental Participant Cost - Incentives)) 1 RTF. Res_Bulbs_v5_2.xlsm RTF. Res_Bulbs_v5_2.xlsm Weighted average of actual fixture sales. Page 17

22 Energy House Calls Segment: Residential 2018 Program Results Cost Inputs Program Administration... $ 160,777 Program Incentives... I Total UC... $ 160,777 P Equipment and Installation (Incremental Participant Cost)... $ M Summary of Cost-Effectiveness Results Test Benefit Cost Ratio UC Test... $ 220,273 $ 160, TRC Test , , RIM Test , , PCT... N/A N/A N/A Net Benefit Inputs (NPV) Resource Savings 2018 Annual Energy (kwh) ,484 NPV Cumulative Energy (kwh)... 4,336,878 $ 220,273 S 10% Credit (Northwest Power Act)... 22,027 Total Electric Savings... $ 242,300 A Participant Bill Savings NPV Cumulative Participant Bill Savings... $ 368,647 B Other Benefits Non-Utility Rebates/Incentives... $ NUI NEBs... $ 37,313 NEB Benefits and Costs Included in Each Test UC Test... = S * NTG = P TRC Test... = (A + NUI + NEB) * NTG = P RIM Test... = S * NTG = P + (B * NTG) PCT... N/A N/A Assumptions for Levelized Calculations Discount Rate Nominal (WACC) % Real ((1 + WACC) / (1 + Escalation)) % Escalation Rate % Net-to- (NTG) % Minimum NTG Sensitivity... 73% Average Customer Segment Rate/kWh... $0.085 Line Losses % Notes: NEBs include PV of periodic bulb (capital) replacement costs for direct-install LED bulbs. NEBs for showerheads include the NPV of water and wastewater savings. No participant costs. Page 18

23 Year: 2018 Program: Energy House Calls Market Segment: Residential Program Type: Energy Efficiency Name Descriptions Replacing PTCS Duct Sealing PTCS Duct Sealing PTCS Duct Sealing PTCS Duct Sealing General Purpose LED Direct Install Low-flow faucet aerator Low-flow showerheads Low-flow showerheads Water heater pipe covers Manufactured Home Prescriptive Duct Sealing - Electric FAF - Heating Zone 1 Manufactured Home Prescriptive Duct Sealing - Electric FAF - Heating Zone 2 or 3 Manufactured Home Prescriptive Duct Sealing - Heat Pump - Heating Zone 1 Manufactured Home Prescriptive Duct Sealing - Heat Pump - Heating Zone 2 or 3 Direct install - LED_General baseline Purpose, Dimmable, and bulb Three-Way_250 to 1049 lumens (Average High Use and Moderate Use) gpm kitchen or bathroom faucet aerator Residential Showerhead Replacement_2_00gpm_Any Shower_ Electric Water Heating_Direct Install Residential Showerhead Replacement_1_75gpm_Any Shower_ Electric Water Heating_Direct Install Up to 6 ft Pre-existing Home duct leakage Pre-existing Home duct leakage Pre-existing Home duct leakage Pre-existing Home duct leakage non- low flow faucet aerator any showerhead 2.2 gpm or higher any showerhead 2.2 gpm or higher No existing coverage Lamp Aerator Showerhead Showerhead Pipe wrap End Use Residential- Manufactured Home Idaho -Heating-All Residential- Manufactured Home Idaho -Heating-All Residential- Manufactured Home Idaho -Heating-All Residential- Manufactured Home Idaho -Heating-All Residential-All- -All Residential-All-Water Heating-Water Heater Residential-All-Water Heating-Water Heater Residential-All-Water Heating-Water Heater Residential-All-Water Heating-Water Heater Life (yrs) a Benefit Cost B/C Tests Annual Energy Savings (kwh/yr) b NPV DSM Avoided Costs c NEB Incremental Participant Cost d Incentive/ Admin Cost ($/kwh) e UCT Ratio f TRC Ratio g Source $ $ , $ $ $ $ $ $ $13.49 $14.25 $ $50.78 $ $84.65 $83.22 $ $ $ $ $61.00 $ a Average measure life. b Estimated kwh savings measured at the customer s meter, excluding line losses. c Sum of NPV of avoided cost. Based on end-use load shape, measure life, savings including line losses, and alternative costs by pricing period as provided in the 2015 IRP. TRC test benefit calculation includes 10% conservation adder from the Northwest Power Act. d No participant costs. e Average program administration and overhead costs to achieve each kwh of savings. Calculated from 2018 actuals. f UCT Ratio = (NPV DSM Avoided Costs) / ((Admin Cost/kWh * kwh Savings) + Incentives) g TRC Ratio = ((NPV DSM Avoided Costs * 110%) + NEB) / ((Admin Cost/kWh * kwh Savings) + Incentives + (Incremental Participant Cost - Incentives)) 1 RTF. ResMHHeatingCoolingPrescriptiveDuctSeal_v2_0.xlsm RTF. Res_Bulbs_v5_2.xlsm AEG. Potential Study RTF. Showerheads_v3_1.xlsm Page 19